Down-dip steam injection for oil recovery

ABSTRACT

In a dipping reservoir which has an active aquifer located downdip, oil is recovered by injecting a slug of steam only slightly updip from the original oil-water contact in the reservoir while concurrently and subsequently producing fluid from at least one location updip from the point of steam injection.

1 1 Mar. 5, 1974 DOWN-DIP STEAM INJECTION FOR OIL RECOVERY [75]Inventors: Derrill G. Whitten, Houston, Tex.; Daryl C. Mclntire,Seymour, Iowa [73] Assignee: Shell Oil Company, Houston, Tex.

[22] Filed: Nov. 10, 1972 [21] Appl. No.2 305,637

[52] U.S.Cl. ..166/272 51 Int. Cl ..E2lb 43/24 [58] Field ofSearch166/272, 303, 245

561 References Cited v UNITED STATES PATENTS 3,319,712 5 1967 QBricn166/245 3,332,485 7/1967 (3611mm 166/245 1? FAULT 1; UP// ,5

3,353,598 11/1967 Smith 166/245 3,360,045 12/1967 Sanlourian.... 166/2693,474,862 lO/l969 Bruisl 1 1 1 166/272 3,477,510 11/1969 Spillettc 1166/272 3,572,437 3/1971 Marbcrry 166/272 Primary Examiner-Stephen J.Novosad Attorney, Agent, or FirmH. W. Coryell [5 7 ABSTRACT In aclipping reservoir which has an active aquifer located down-dip, oil isrecovered by injecting a slug of steam only slightly updip from theoriginal oil-water contact in the reservoir while concurrently andsubsequently producing fluid from at least one location updip from thepoint of steam injection.

4 Claims, 4 Drawing Figures COLD O/L BANK STEAM ZONE STEAM INJECTORPATENTED 5 I974 CUMULATIVE INJECTION AND PRODUCTION, PORE VOLUMES3.795.278 sum 1 uf 2 F/OI COLD OIL BANK 72 STEAII I ZONE INJECTION ANDPRODUCTION HISTORY, "LEAPFROO" PROCEDURE USING TWO INJECTORS CUMULATIVESTEAM INJECT WELL 5 OIL /STEAM RAT/O CUMULATIVE OIL l l l l l CUMULATIVEINJECTION AND PRODUCTION, PORE VOLUMES PATENTEI] "AR 5 I974 CUMULATIVEOIL/STEAM RA TIO, bbI/bb/ SHEET 2 OF 2 UPPER STEAM ZONE 3 UPD/P STEAMINJECTOR COLD OIL BANK LOWER STEAM ZONE STEAM INJECTOR +WATER PRODUCERCUMULATIVE STEAM OIL /STEAM RATIO CUMULA T/VE OIL INJECTION ANDPRODUCTION HIS TOR Y, COMB/NA T/ON PROCESS YEARS 6 4 DOWN-DIP STEAMINJECTION FOR OIL v RECOVERY BACKGROUND OF THE INVENTION This inventionrelates to a steam drive oil production process. More particularly, itrelates to producing a relatively viscous oil from a dipping reservoirin which the influx of water from a downdip aquifer causes an updipmigration of water within the reservoir whenever more fluid is producedthan is injected.

In such a reservoir, the permeability may be high and this may aggravateproblems due to gravity segregation. In addition, severe problems areposed by the influx of water. If a'conventional type of steam flood isused in such a reservoir, it may be necessary to establish and maintainan undesirably high pressure in the reservoir, and/or to pump offsubstantially all of the water that tends to enter the productionpattern. The injected steam tends to form a thin steam zone that extendsbetween wells along the uppermost portion of the reservoir and gravitycauses the liquid flow to be directed predominately downdip. Theinjected steam causes a cold oil bank to be developed downdip from theinjection wells in a manner that may require an undesirably high fluidinjection pressure in order to displace the oil.

SUMMARY OF THE INVENTION This invention relates to a steam drive processfor producing a relatively viscous oil from a dipping subterraneanreservoir located updip from an active aquifer from which water inflowswhenever more fluid is produced than is injected at a location above theoriginal oil-water contact within 'the reservoir. Fluid is produced fromthe reservoir at two or more locations, with one being farther updipfrom the oil-water contact than another and with the fluid beingproduced at a rate that causesan inflow of water into the reservoir. Adiscrete slug ofsteam is injected into the reservoir at one or morelocations that isupdip from the oil-water contact but downdip from thefarthest downdip fluid production location, with the steam beinginjected at a rate and pressure sufficient to divert inflowing wateraround at least one steam zone that is forming and expanding within thereservoir. The production of fluid from the reservoir is continued afterthe steam slug has been injected. The production from the farthestdowndip location is terminated after the water cut has increased to aselected economic limit due to encroaching water influx, e.g., to awater concentration such as about 98 percent or more.

In one preferred embodiment, at least one such downdip steam sluginjection with updip production operation is combined with an updipoperation in which steam is injected near the uppermost boundary of thereservoir while fluid is produced from at least one location near butdowndip from the latter steam injection location. In another preferredembodiment, where the oil-containing portion of the reservoir contains arelatively centrally located layer or streak of material having apermeability that is significantly less than that of other portions ofthe reservoir, in each steam injection step, the steam is injected at adepth within the reservoir that underlies the layer of relatively lowpermeability. I

DESCRIPTION OF THE DRAWING FIG. 1 is a schematic illustration of aportion of a reservoir being treated in accordance with this invention.FIG. 2 is a graphical illustration of the results of employing oneembodiment of the invention. FIG. 3 is a schematic illustration of aportion of the reservoir being treated in accordance with a combinedupdip and downdip embodiment of the invention. FIG. 4 is a graphicillustration of the results of employing combination updip and downdipembodiment of the invention.

DESCRIPTION OF THE INVENTION This invention is applicable tosubstantially any subterranean reservoir that: (l) is inclined by atleast about 3 to the horizontal; (2) is sufficiently permeable (e.g.,having a permeability of at least about 200 millidarcies) to permit aneconomically feasible rate of displacement of fluid within the reservoirin response to pressure less than the fracturing pressure of thereservoir; (3) contains an oil which is relatively viscous at thereservoir temperature; and (4) is interconnected with an active sourceof natural water located downdip of the oil-bearing sands in a mannersuch that the water encroachment within the reservoir tends to moveupdip whenever fluid is produced from above the oil-water contact in amanner that reduces the total amount of fluid and/or pressure within theupper portion of the reservoir.

A model of such a reservoir is shown in FIG. 1. The model comprises arectangular sand pack which is scaled to represent a reservoir sandhaving a thickness of about feet thick; awidth of about 500 feet, alongthe strike of a 6 dipping bed; and a length of about 4000 feet, alongthe dip of the bed. The reservoir sand has a permeability of about 5darcies throughout all portions except a layer (equivalent to an 8 footthick layer of the reservoir) which is located about one-third thedistance from the bottom and has a permeability of 0.5 darcies. Theinflux of aquifer water is simulated by injecting water through amanifold at the downdip end of the model at a rate equivalent to 2300barrels per day. The model is provided with simulated wells 1-9 and Bthrough which fluids can be injected or produced.

The behavior of the model shown in FIG. 1 is relatively accuratelyindicative of the behavior of an actual subterranean reservoir withrespect to the response to an injection of steam or water and theproduction of fluid, the distribution of heat, and the like.

In respect to such a reservoir, steam injection experiments indicatethat a number of difiiculties are encountered by conventional steamdrive oil recovery operation. In typical examples of such experiments,steam was injected into wells 1 and 3 at rates equivalent to about 2000barrels per day and an amount equivalent to 0.7 pore volumes, using anaverage injection pressure corresponding To 200 psig in the field. Wells2,4,5,6,7 and 8 were produced at rates up to 1500 barrels per day whilewell 9, the well nearest the original oil-water contact was produced atabout 3000 barrels per day. Where the rate of aquifer water influx wasabout 3000 barrels per day, the injected steam formed a steam zone whichoverlaid the entire upper portion of the reservoir and formed a cold oilbank that extended downdip to a point that eventually reached well 8.Most of the oil was produced in the more downdip wells 6, 7 and 8. Theproduction involved high rates and unrealistic negative prototypeproduction pressures. This indicated that for such an oil recoveryprocess to work it would be necessary to employ additional infillproduction wells, higher steam zone pressure levels, or some type ofstimulation for the downdip wells. Similar production problems wereindicated by analogous experiments in which the steam was injected intoa single updip well.

In such a reservoir situation the above type of difficulties (whichinvolve the tendency for steam overrunning, water influx, steam zonecollapsing by an influx of cold water, and the like) are indicative ofthe inapplicability of previously known steam drive oil productionprocesses to such a reservoir. With respect to such prior processes, USPat. No. 3,572,437 indicates that an injection of steam should befollowed by an injection of hot water since a process of first steamflooding and then injecting water (e.g., as suggested in US Pats. Nos.3,353,598 or 3,360,045) are apt to involve a disadvantageous cold waterinflux induced collapse of the steam zone. In a water drive reservoir ofthe type to which the present invention is applicable, the avoidance ofthe enroachment by the relatively cool aquifer water would be unfeasiblyexpensive to avoid. US Pat. No. 3,477,510 indicates that in a reservoirin which gravity segregation is apt to occur, a steam drive should beeffected by injecting alternating slugs of steam and water in order toavoid steam overrunning and the water underrunning. In a water drivereservoir, a water encroachment occurs whenever more fluid is producedthan is injected, and the encroachment prevention and alternating slugmode of operation would be unfeasibly expensive.

FIG. I shows an early stage (after simulated six months injection ofsteam) of application of the present process to a dipping andinhomogeneous reservoir in which there is a significant water drive fromdowndip. In the illustrated experiment, the steam was injected throughwell B at a rate equivalent to 1850 barrels per day. The reservoir oilsaturation at the beginning of the steam injection was 50 percent. Aconstant 2300 barrels per day water influx was simulated throughout theexperiment by an injection through a special manifold at the downdip endof the model. During the steam injection, wells 2-6 were produced atrates up to 1000 barrels per day. Two years of steam injection produceda steam zone which extended 200 feet downdip from the injection well Band about 1800 feet updip to just beyond Well 3.

A reservoir of the type to which the present invention is applicable isapt to be inhomogeneous. Such inhomogeneties are apt to comprise a layeror zone that is: thin relative to the total thickness of the reservoir,extends along substantially all of the reservoir, and is relativelycentrally located within the reservoir. The reservoir shown in FIG. 1contains a low permeability layer (permeability 0.5 darcies) locatedabout one-third the distance from the bottom sand of the reservoir(permeability of S darcies). The tight streak is about 8 feet (i.e., athin layer relative to the 75-foot thick reservoir) and extends alongsubstantially all portions of the reservoir within the productionpattern. In a preferred manner of operating the present invention, thesteam is injected into such a reservoir so that it is forced to enterthe portion below such a streak or tight zone. As shown in FIG. 1, suchan injection procedure causes the expanding steam zone 11 to partiallyunderrun such a tight streak by forming steam zone fingers such as 11a.Such underrunning tends to improve the vertical profile of the steamzone and thus tends to reduce the bypassing of the oil that is to bedisplaced ahead of the steam zone to form the cold oil bank 12.

FIG. 2 shows the result of repetitive or leap frog use of the downdipsteam slug injection process of this invention. While fluid was beingproduced from a series of wells located along dip, steam was injected insuccession through well 9 and well 5. The experiment was continued untila total of 0.6. pore volumes of steam was injected into a reservoirhaving a 60 percent initial oil saturation. As will be apparent from theinjection production history on the graph, the oil recovery amounted toabout 0.2 pore volumes of oil recovered at an oil steam ratio ofslightly more than 0.3, during a 10 year period. An analogous experimentin which a similar amount of steam was'injected in succession throughwells 9, 6 and 3 indicated that the attainment of such results arerelatively insensitive to the number of wells that are so employed.

In various stages of the present process it is desirable to producefluid from wells which have been reached by a portion of the expandingsteam zone within the reservoir. As known to those skilled in the art,numerous procedures can be utilized to maintain a suitable efiiciency ofoil production. For example, gas anchors, and/or downhole gas-liquidsegregation into conduits arranged for separate production of liquid andgas, two stage pumping systems, or the like procedures can be used. In aparticular suitable procedure. a pumping device can be supercharged bymeans of a jet-pump through which a small amount of power fluid isinjected to prevent vapor-locking within the pump section chamber, asdescribed in the co-pending patent application Ser. No. 254,276, filedMay 17, l972.

Experiments such as those described above indicate that certainadvantages and limitations are involved in either updip or downdip steaminjection processes with respect to a field-wide recovery process. Theupdip steam injection is efficient in driving the oil into the upper andmiddle portion of the reservoir but the aquifer influx must be producedwithin the downdip part of the reservoir, either from high volumeproducers or by special well located near the oil-water contact. Thedowndip steam slug injection is effective in recovering oil from nearthe oil-water contact, and is relatively uneffected by the aquiferbehavior, but a relatively low oil/steam ratio is obtained and a longproduction time would be required to extend such a procedure to theupdip area. Thus, a combination of the updip and downdip processes mightpossibly enhance the advantages of each other.

FIG. 3 shows the dispositions of an upper steam zone 16 and a lowersteam zone 17 after a simulated 1.6 year injection of steam into wells 3and 8.

In the completed experiment, a total of 0.7 pore volumes of steam wasinjected into the updip well 3 at rates up to 2000 barrels per day overa 10-year period while 02 pore volumes was injected into the downdipwell '8 during the first 2 years. After being shut in for one year,i.e., during the third year of the experiment, well 8 was operated as aproducing well that produced 1800 barrels per day of fluid for theremainder of the experiment. A constant aquifer-water influx of 2300 ingwells. As a result, the downdip producers were able to produce at highoil rates without the draw-down problems that were indicated when theupdip continuous injection process was employed by itself.

FIG. 4 shows the injection and production results. An oil recovery of0.34 pore volumes was attained at an oil-steam ratio of 0.39 and sincethe updip and downdip injection procedures were found to complement eachother, the process performs as a summation of the two processes.

An analogous experiment in which well 1 (located only 65 feet from theupdip fault) was used as the upper injector (instead ofwell 3), producedsubstantially similar results. This indicates that the oil recovery isrelatively unaffected by the position of the updip injector along thedip. This allows flexibility relative to operational ease or theavailability of an existing well pattern or the like, with respect toselecting the location of the updip wells.

.In an analogous experiment, Well 8 was not produced (after theinjection of the downdip steam slug) so that the full 2300 barrels perday of water influx was produced from wells 7, 6 and 5. The maximumgross rate of fluid production of these wells was increased to handlethe added influx of water. The overall oil recovery was substantiallyunchanged, indicating that the efficiency is good as long as the aquiferinflux is produced in the most downdip two or three rows of wells.

An analogous experiment in which a 1000 barrel per day aquifer influxwas simulated during the first two years indicated, in spite of such avariation, the oil recovery was substantially unchanged. In a fieldoperation, during the initial period such a decrease in aquifer influxmight be caused by the pressure build-up resulting from the injection ofthe downdip steam slug.

What is claimed is:

1. In a steam drive process for producing oil from a dipping oilreservoir located just updip from an aquifer from which Water inflowswhen fluid is produced from within the reservoir updip of the oil-watercontact the improvement which comprises:

producing fluid from at least two locations at different distances updipfrom the oil-water contact at a rate causing an inflow of water into thereservoir;

injecting a slug of steam in at least one location updip from theoil-water contact but downdip from the farthest downdip productionlocation; injecting the steam at a rate and pressure sufficient todivert the inflowing water around an expanding steam zone; and

continuing the fluid production after-the steam slug has been injectedat least until the water cut has reached a selected limit in at leastthe farthest downdip production location.

2. The process of claim 1 including the step of repeating said downdipsteam slug injection and fluid production by injecting at least oneadditional downdip slug of steam into at least one additional locationthat is updip from the first injection location but downdip from thethen existing downdip production location.

3. The process of claim 1 in which the reservoir contains a centrallylocated layer having a relatively low permeability and said steam slugis injected selectively into a depth interval lower than the top of saidlayer.

duction location.

mg UNITED STATES PATENT OFFICE CERTIFICATE OF CORRECTION March 5, 1974Patent No. 3,795,278 Dated Inventor) DERRILL G. WHITTEN It is certifiedthat error appears in the above-identified patent and that said LettersPatent are hereby corrected as shown below:

The inventorship should read:

"In'vehtor: Derrill G. Whitten, Houston, Texas" Signed and sealed this9th day of July 1974p.

(SEAL) Attest: i I MCCOY M.GIBSON,JR. c. MARSHALL DANN Attesting OfficerCommissioner. of Patents

1. In a steam drive process for producing oil from a dipping oilreservoir located just updip from an aquifer from which water inflowswhen fluid is produced from within the reservoir updip of the oil-watercontact the improvement which comprises: producing fluid from at leasttwo locations at different distances updip from the oil-water contact ata rate causing an inflow of water into the reservoir; injecting a slugof steam in at least one location updip from the oil-water contact butdowndip from the farthest downdip production location; injecting thesteam at a rate and pressure sufficient to divert the inflowing wateraround an expanding steam zone; and continuing the fluid productionafter the steam slug has been injected at least until the water cut hasreached a selected limit in at least the farthest downdip productionlocation.
 2. The process of claim 1 including the step of repeating saiddowndip steam slug injection and fluid production by injecting at leastone additional downdip slug of steam into at least one additionallocation that is updip from the first injection location but downdipfrom the then existing downdip production location.
 3. The process ofclaim 1 in which the reservoir contains a centrally located layer havinga relatively low permeability and said steam slug is injectedselectively into a depth interval lower than the top of said layer. 4.The process of claim 1 in which steam is injected into at least onelocation updip from at least one production location.